(Former name, former address and former fiscal year, if changed since last report.)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ

Accelerated filer ¨

Non-accelerated filer ¨

Smaller reporting company ¨

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

This quarterly report on Form 10-Q of Chevron Corporation contains forward-looking statements relating to Chevron’s operations that are based on management’s current expectations, estimates and projections about the petroleum, chemicals and other energy-related industries. Words such as “anticipates,” “expects,” “intends,” “plans,” “targets,” “forecasts,” “projects,” “believes,” “seeks,” “schedules,” “estimates,” “budgets,” “outlook” and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond the company’s control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, Chevron undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are: changing crude oil and natural gas prices; changing refining, marketing and chemical margins; actions of competitors or regulators; timing of exploration expenses; timing of crude oil liftings; the competitiveness of alternate-energy sources or product substitutes; technological developments; the results of operations and financial condition of equity affiliates; the inability or failure of the company’s joint-venture partners to fund their share of operations and development activities; the potential failure to achieve expected net production from existing and future crude oil and natural gas development projects; potential delays in the development, construction or start-up of planned projects; the potential disruption or interruption of the company’s net production or manufacturing facilities or delivery/transportation networks due to war, accidents, political events, civil unrest, severe weather or crude oil production quotas that might be imposed by the Organization of Petroleum Exporting Countries; the potential liability for remedial actions or assessments under existing or future environmental regulations and litigation; significant investment or product changes under existing or future environmental statutes, regulations and litigation; the potential liability resulting from other pending or future litigation; the company’s future acquisition or disposition of assets and gains and losses from asset dispositions or impairments; government-mandated sales, divestitures, recapitalizations, industry-specific taxes, changes in fiscal terms or restrictions on scope of company operations; foreign currency movements compared with the U.S. dollar; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; and the factors set forth under the heading “Risk Factors” on pages 29 through 31 of the company’s 2011 Annual Report on Form 10-K. In addition, such results could be affected by general domestic and international economic and political conditions. Other unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements.

The accompanying consolidated financial statements of Chevron Corporation and its subsidiaries (the company) have not been audited by an independent registered public accounting firm. In the opinion of the company’s management, the interim data include all adjustments necessary for a fair statement of the results for the interim periods. These adjustments were of a normal recurring nature. The results for the three- and nine-month periods ended September 30, 2012, are not necessarily indicative of future financial results. The term “earnings” is defined as net income attributable to Chevron Corporation.

Certain notes and other information have been condensed or omitted from the interim financial statements presented in this Quarterly Report on Form 10-Q. Therefore, these financial statements should be read in conjunction with the company’s 2011 Annual Report on Form 10-K.

Note 2. Noncontrolling Interests

Ownership interests in the company’s subsidiaries held by parties other than the parent are presented separately from the parent’s equity on the Consolidated Balance Sheet. The amount of consolidated net income attributable to the parent and the noncontrolling interests are both presented on the face of the Consolidated Statement of Income.

Activity for the equity attributable to noncontrolling interests for the first nine months of 2012 and 2011 is as follows:

2012

2011

Chevron Corporation

Stockholders’ Equity

Noncontrolling

Interest

Total

Equity

Chevron Corporation

Stockholders’ Equity

Noncontrolling

Interest

Total

Equity

(Millions of dollars)

Balance at January 1

$

121,382

$

799

$

122,181

$

105,081

$

730

$

105,811

Net income

18,934

105

19,039

21,772

84

21,856

Dividends

(5,102

)

—

(5,102

)

(4,541

)

—

(4,541

)

Distributions to noncontrolling interests

—

(23

)

(23

)

—

(56

)

(56

)

Treasury shares, net

(3,017

)

—

(3,017

)

(2,148

)

—

(2,148

)

Other changes, net*

744

400

1,144

727

27

754

Balance at September 30

$

132,941

$

1,281

$

134,222

$

120,891

$

785

$

121,676

_________________________________

*

Primarily includes components of comprehensive income, which are disclosed separately in the Consolidated Statement of Comprehensive Income.

The “Net (increase) decrease in operating working capital” was composed of the following operating changes:

Nine Months Ended September 30

2012

2011

(Millions of dollars)

Decrease (increase) in accounts and notes receivable

$

757

$

(1,215

)

Increase in inventories

(2,068

)

(919

)

Increase in prepaid expenses and other current assets

(841

)

(904

)

Increase in accounts payable and accrued liabilities

25

2,493

(Decrease) increase in income and other taxes payable

(821

)

2,049

Net (increase) decrease in operating working capital

$

(2,948

)

$

1,504

The “Net (increase) decrease in operating working capital” includes reductions of $87 million and $132 million for excess income tax benefits associated with stock options exercised during the nine months ended September 30, 2012, and 2011, respectively. These amounts are offset by an equal amount in “Net purchases of treasury shares.”

“Net Cash Provided by Operating Activities” included the following cash payments for interest on debt and for income taxes:

Nine Months Ended September 30

2012

2011

(Millions of dollars)

Interest on debt (net of capitalized interest)

$

32

$

46

Income taxes

14,345

12,982

"Other" includes changes in postretirement benefits obligations and other long-term liabilities.

The Consolidated Statement of Cash Flow for the 2012 period excludes the effects of $800 million of proceeds to be received in future periods for the sale of an equity interest in the Wheatstone Project.

Information related to "Restricted Cash" is included on page 20 in Note 11 under the heading "Restricted Cash."

The “Net sales (purchases) of time deposits” consisted of the following gross amounts:

Nine Months Ended September 30

2012

2011

(Millions of dollars)

Time deposits purchased

$

(17

)

$

(6,439

)

Time deposits matured

3,967

3,435

Net sales (purchases) of time deposits

$

3,950

$

(3,004

)

The “Net purchases of marketable securities” consisted of the following gross amounts:

Nine Months Ended September 30

2012

2011

(Millions of dollars)

Marketable securities purchased

$

(35

)

$

(113

)

Marketable securities sold

31

38

Net purchases of marketable securities

$

(4

)

$

(75

)

The “Net purchases of treasury shares” represents the cost of common shares acquired less the cost of shares issued for share-based compensation plans. Purchases totaled $3.8 billion and $3.0 billion in the first nine months of 2012 and 2011, respectively. During the first nine months of 2012 and 2011, the company purchased 35.1 million and 30.0 million common shares for $3.7 billion and $3.0 billion under its ongoing share repurchase program, respectively.

The major components of “Capital expenditures” and the reconciliation of this amount to the capital and exploratory expenditures, including equity affiliates, are as follows:

Although each subsidiary of Chevron is responsible for its own affairs, Chevron Corporation manages its investments in these subsidiaries and their affiliates. The investments are grouped into two business segments, Upstream and Downstream, representing the company’s “reportable segments” and “operating segments” as defined in accounting standards for segment reporting (ASC 280). Upstream operations consist primarily of exploring for, developing and producing crude oil and natural gas; liquefaction, transportation and regasification associated with liquefied natural gas (LNG); transporting crude oil by major international oil export pipelines; processing, transporting, storage and marketing of natural gas; and a gas-to-liquids project. Downstream operations consist primarily of refining of crude oil into petroleum products; marketing of crude oil and refined products; transporting of crude oil and refined products by pipeline, marine vessel, motor equipment and rail car; and manufacturing and marketing of commodity petrochemicals, plastics for industrial uses, and fuel and lubricant additives. All Other activities of the company include mining operations, power generation businesses, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, energy services, and alternative fuels and technology companies.

The segments are separately managed for investment purposes under a structure that includes “segment managers” who report to the company’s “chief operating decision maker” (CODM) (terms as defined in ASC 280). The CODM is the company’s Executive Committee (EXCOM), a committee of senior officers that includes the Chief Executive Officer, and EXCOM reports to the Board of Directors of Chevron Corporation.

The operating segments represent components of the company, as described in accounting standards for segment reporting (ASC 280), that engage in activities (a) from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the CODM, which makes decisions about resources to be allocated to the segments and assesses their performance; and (c) for which discrete financial information is available.

Segment managers for the reportable segments are directly accountable to and maintain regular contact with the company’s CODM to discuss the segment’s operating activities and financial performance. The CODM approves annual capital and exploratory budgets at the reportable segment level, as well as reviews capital and exploratory funding for major projects and approves major changes to the annual capital and exploratory budgets. However, business-unit managers within the operating segments are directly responsible for decisions relating to project implementation and all other matters connected with daily operations. Company officers who are members of the EXCOM also have individual management responsibilities and participate in other committees for purposes other than acting as the CODM.

The company’s primary country of operation is the United States of America, its country of domicile. Other components of the company’s operations are reported as “International” (outside the United States).

Segment Earnings The company evaluates the performance of its operating segments on an after-tax basis, without considering the effects of debt financing interest expense or investment interest income, both of which are managed by the company on a worldwide basis. Corporate administrative costs and assets are not allocated to the operating segments. However, operating segments are billed for the direct use of corporate services. Nonbillable costs remain at the corporate level in “All Other.” Earnings by major operating area for the three- and nine-month periods ended September 30, 2012, and 2011, are presented in the following table:

Segment Sales and Other Operating Revenues Segment sales and other operating revenues, including internal transfers, for the three- and nine-month periods ended September 30, 2012, and 2011, are presented in the following table. Products are transferred between operating segments at internal product values that approximate market prices. Revenues for the upstream segment are derived primarily from the production and sale of crude oil and natural gas, as well as the sale of third-party production of natural gas. Revenues for the downstream segment are derived from the refining and marketing of petroleum products such as gasoline, jet fuel, gas oils, lubricants, residual fuel oils and other products derived from crude oil. This segment also generates revenues from the manufacture and sale of fuel and lubricant additives and the transportation and trading of refined products and crude oil. “All Other” activities include revenues from mining operations, power generation businesses, insurance operations, real estate activities, energy services, and alternative fuels and technology companies.

Chevron U.S.A. Inc. (CUSA) is a major subsidiary of Chevron Corporation. CUSA and its subsidiaries manage and operate most of Chevron’s U.S. businesses. Assets include those related to the exploration and production of crude oil, natural gas and natural gas liquids and those associated with refining, marketing, and supply and distribution of products derived from petroleum, excluding most of the regulated pipeline operations of Chevron. CUSA also holds the company’s investment in the Chevron Phillips Chemical Company LLC joint venture, which is accounted for using the equity method.

During 2012, Chevron implemented legal reorganizations in which certain Chevron subsidiaries transferred assets to or under CUSA. The summarized financial information for CUSA and its consolidated subsidiaries presented in this table below gives retroactive effect to the reorganizations as if they had occurred on January 1, 2011. However, the financial information in the following table may not reflect the financial position and operating results in the periods presented if the reorganization had occurred on that date.

The summarized financial information for CUSA and its consolidated subsidiaries is as follows:

Nine Months Ended September 30

2012

2011

(Millions of dollars)

Sales and other operating revenues

$

139,107

$

143,014

Costs and other deductions

132,534

135,249

Net income attributable to CUSA

4,734

5,733

At September 302012

At December 312011

(Millions of dollars)

Current assets

$

20,105

$

34,490

Other assets

49,751

47,556

Current liabilities

18,577

19,081

Other liabilities

26,439

26,160

Total CUSA net equity

$

24,840

$

36,805

Memo: Total debt

$

14,475

$

14,763

Note 6. Summarized Financial Data — Chevron Transport Corporation

Chevron Transport Corporation Limited (CTC), incorporated in Bermuda, is an indirect, wholly owned subsidiary of Chevron Corporation. CTC is the principal operator of Chevron’s international tanker fleet and is engaged in the marine transportation of crude oil and refined petroleum products. Most of CTC’s shipping revenue is derived from providing transportation services to other Chevron companies. Chevron Corporation has fully and unconditionally guaranteed this subsidiary’s obligations in connection with certain debt securities. Summarized financial information for CTC and its consolidated subsidiaries is as follows:

There were no restrictions on CTC’s ability to pay dividends or make loans or advances at September 30, 2012.

Note 7. Income Taxes

Taxes on income for the third quarter and first nine months of 2012 were $4.6 billion and $15.3 billion, respectively, compared with $5.5 billion and $15.8 billion for the corresponding periods in 2011. The associated effective tax rates (calculated as the amount of Income Tax Expense divided by Income Before Income Tax Expense) for the third quarters of 2012 and 2011 were 47 percent and 41 percent, respectively. For the comparative nine-month periods, the effective tax rates were 45 percent and 42 percent, respectively.

The increase in the effective tax rate between quarterly periods was primarily due to foreign currency remeasurement impacts and an increased percentage of earnings in international jurisdictions with high tax rates. The impact from non-U.S. upstream asset sales on the effective tax rate in the current quarter was essentially offset by the effect of non-U.S. downstream asset sales in the comparative 2011 period. The increase in the effective tax rate for the nine-month comparison primarily reflected a lower utilization of tax credits in non-U.S. jurisdictions in the current period and foreign currency remeasurement impacts between periods.

Tax positions for Chevron and its subsidiaries and affiliates are subject to income tax audits by many tax jurisdictions throughout the world. For the company’s major tax jurisdictions, examinations of tax returns for certain prior tax years had not been completed as of September 30, 2012. For these jurisdictions, the latest years for which income tax examinations had been finalized were as follows: United States — 2007, Nigeria — 2000, Angola — 2001, Saudi Arabia — 2003 and Kazakhstan — 2006.

The company engages in ongoing discussions with tax authorities regarding the resolution of tax matters in the various jurisdictions. Both the outcome of these tax matters and the timing of resolution and/or closure of the tax audits are highly uncertain. However, it is reasonably possible that developments on tax matters in certain tax jurisdictions may result in significant increases or decreases in the company’s total unrecognized tax benefits within the next 12 months. Given the number of years that still remain subject to examination and the number of matters being examined in the various tax jurisdictions, the company is unable to estimate the range of possible adjustments to the balance of unrecognized tax benefits.

Note 8. Employee Benefits

Chevron has defined benefit pension plans for many employees. The company typically prefunds defined benefit plans as required by local regulations or in certain situations where prefunding provides economic advantages. In the United States, all qualified plans are subject to the Employee Retirement Income Security Act (ERISA) minimum funding standard. The company does not typically fund U.S. nonqualified pension plans that are not subject to funding requirements under laws and regulations because contributions to these pension plans may be less economic and investment returns may be less attractive than the company’s other investment alternatives.

The company also sponsors other postretirement (OPEB) plans that provide medical and dental benefits, as well as life insurance for some active and qualifying retired employees. The plans are unfunded, and the company and the retirees share the costs. Medical coverage for Medicare-eligible retirees in the company’s main U.S. medical plan is secondary to Medicare (including Part D) and the increase to the company contribution for retiree medical coverage is limited to no more than 4 percent each year. Certain life insurance benefits are paid by the company.

The components of net periodic benefit costs for 2012 and 2011 are as follows:

Three Months EndedSeptember 30

Nine Months Ended September 30

2012

2011

2012

2011

(Millions of dollars)

Pension Benefits

United States

Service cost

$

113

$

94

$

339

$

281

Interest cost

109

116

327

347

Expected return on plan assets

(158

)

(154

)

(475

)

(460

)

Amortization of prior service credits

(2

)

(2

)

(6

)

(6

)

Amortization of actuarial losses

117

77

352

232

Settlement losses

65

52

204

196

Total United States

244

183

741

590

International

Service cost

45

44

135

132

Interest cost

79

81

241

243

Expected return on plan assets

(67

)

(71

)

(201

)

(208

)

Amortization of prior service costs

5

3

14

15

Amortization of actuarial losses

32

23

102

79

Curtailment losses

—

—

—

36

Total International

94

80

291

297

Net Periodic Pension Benefit Costs

$

338

$

263

$

1,032

$

887

Other Benefits*

Service cost

$

16

$

14

$

46

$

44

Interest cost

37

46

114

136

Amortization of prior service credits

(18

)

(18

)

(54

)

(54

)

Amortization of actuarial losses

13

17

42

48

Settlement gains

—

—

(26

)

—

Net Periodic Other Benefit Costs

$

48

$

59

$

122

$

174

_________________________________

*

Includes costs for U.S. and international OPEB plans. Obligations for plans outside the U.S. are not significant relative to the company’s total OPEB obligation.

At the end of 2011, the company estimated it would contribute $900 million to employee pension plans during 2012 (composed of $600 million for the U.S. plans and $300 million for the international plans). Through September 30, 2012, a total of $1.03 billion was contributed (including $840 million to the U.S. plans). Total contributions for the full year are currently estimated to be $1.15 billion ($850 million for the U.S. plans and $300 million for the international plans). Actual contribution amounts are dependent upon plan investment returns, changes in pension obligations, regulatory requirements and other economic factors. Additional funding may ultimately be required if investment returns are insufficient to offset increases in plan obligations.

During the first nine months of 2012, the company contributed $150 million to its OPEB plans. The company anticipates contributing approximately $70 million during the remainder of 2012.

Note 9. Litigation

MTBE Chevron and many other companies in the petroleum industry have used methyl tertiary butyl ether (MTBE) as a gasoline additive. Chevron is a party to seven pending lawsuits and claims, the majority of which involve numerous other petroleum marketers and refiners. Resolution of these lawsuits and claims may ultimately require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future. The company’s ultimate exposure related to pending lawsuits and claims is not determinable. The company no longer uses MTBE in the manufacture of gasoline in the United States.

Ecuador Chevron is a defendant in a civil lawsuit before the Superior Court of Nueva Loja in Lago Agrio, Ecuador, brought in May 2003 by plaintiffs who claim to be representatives of certain residents of an area where an oil production consortium formerly had operations. The lawsuit alleges damage to the environment from the oil exploration and production operations and seeks unspecified damages to fund environmental remediation and restoration of the alleged environmental harm, plus a health monitoring program. Until 1992, Texaco Petroleum Company (Texpet), a subsidiary of Texaco Inc., was a minority member of this consortium with Petroecuador, the Ecuadorian state-owned oil company, as the majority partner; since 1990, the operations have been conducted solely by Petroecuador. At the conclusion of the consortium and following an independent third-party environmental audit of the concession area, Texpet entered into a formal agreement with the Republic of Ecuador and Petroecuador for Texpet to remediate specific sites assigned by the government in proportion to Texpet’s ownership share of the consortium. Pursuant to that agreement, Texpet conducted a three-year remediation program at a cost of $40 million. After certifying that the sites were properly remediated, the government granted Texpet and all related corporate entities a full release from any and all environmental liability arising from the consortium operations.

Based on the history described above, Chevron believes that this lawsuit lacks legal or factual merit. As to matters of law, the company believes first, that the court lacks jurisdiction over Chevron; second, that the law under which plaintiffs bring the action, enacted in 1999, cannot be applied retroactively; third, that the claims are barred by the statute of limitations in Ecuador; and, fourth, that the lawsuit is also barred by the releases from liability previously given to Texpet by the Republic of Ecuador and Petroecuador and by the pertinent provincial and municipal governments. With regard to the facts, the company believes that the evidence confirms that Texpet’s remediation was properly conducted and that the remaining environmental damage reflects Petroecuador’s failure to timely fulfill its legal obligations and Petroecuador’s further conduct since assuming full control over the operations.

In 2008, a mining engineer appointed by the court to identify and determine the cause of environmental damage, and to specify steps needed to remediate it, issued a report recommending that the court assess $18.9 billion, which would, according to the engineer, provide financial compensation for purported damages, including wrongful death claims, and pay for, among other items, environmental remediation, health care systems and additional infrastructure for Petroecuador. The engineer’s report also asserted that an additional $8.4 billion could be assessed against Chevron for unjust enrichment. In 2009, following the disclosure by Chevron of evidence that the judge participated in meetings in which businesspeople and individuals holding themselves out as government officials discussed the case and its likely outcome, the judge presiding over the case was recused. In 2010, Chevron moved to strike the mining engineer’s report and to dismiss the case based on evidence obtained through discovery in the United States indicating that the report was prepared by consultants for the plaintiffs before being presented as the mining engineer’s independent and impartial work and showing further evidence of misconduct. In August 2010, the judge issued an order stating that he was not bound by the mining engineer’s report and requiring the parties to provide their positions on damages within 45 days. Chevron subsequently petitioned for recusal of the judge, claiming that he had disregarded evidence of fraud and misconduct and that he had failed to rule on a number of motions within the statutory time requirement.

In September 2010, Chevron submitted its position on damages, asserting that no amount should be assessed against it. The plaintiffs’ submission, which relied in part on the mining engineer’s report, took the position that damages are between approximately $16 billion and $76 billion and that unjust enrichment should be assessed in an amount between approximately $5 billion and $38 billion. The next day, the judge issued an order closing the evidentiary phase of the case and notifying the parties that he had requested the case file so that he could prepare a judgment. Chevron petitioned to have that order declared a nullity in light of Chevron’s prior recusal petition, and because procedural and evidentiary matters remained unresolved. In October 2010, Chevron’s motion to recuse the judge was granted. A new judge took charge of the case and revoked the prior judge’s order closing the evidentiary phase of the case. On December 17, 2010, the judge issued an order closing the evidentiary phase of the case and notifying the parties that he had requested the case file so that he could prepare a judgment.

On February 14, 2011, the provincial court in Lago Agrio rendered an adverse judgment in the case. The court rejected Chevron’s defenses to the extent the court addressed them in its opinion. The judgment assessed

approximately $8.6 billion in damages and approximately $900 million as an award for the plaintiffs’ representatives. It also assessed an additional amount of approximately $8.6 billion in punitive damages unless the company issued a public apology within 15 days of the judgment, which Chevron did not do. On February 17, 2011, the plaintiffs appealed the judgment, seeking increased damages, and on March 11, 2011, Chevron appealed the judgment seeking to have the judgment nullified. On January 3, 2012, an appellate panel in the provincial court affirmed the February 14, 2011 decision and ordered that Chevron pay additional attorneys’ fees in the amount of “0.10% of the values that are derived from the decisional act of this judgment.” The plaintiffs filed a petition to clarify and amplify the appellate decision on January 6, 2012, and the court issued a ruling in response on January 13, 2012, purporting to clarify and amplify its January 3, 2012 ruling, which included clarification that the deadline for the company to issue a public apology to avoid the additional amount of approximately $8.6 billion in punitive damages was within 15 days of the clarification ruling, or February 3, 2012. Chevron did not issue an apology because doing so might be mischaracterized as an admission of liability and would be contrary to facts and evidence submitted at trial. On January 20, 2012, Chevron appealed (called a petition for cassation) the appellate panel’s decision to Ecuador’s National Court of Justice. As part of the appeal, Chevron requested the suspension of any requirement that Chevron post a bond to prevent enforcement under Ecuadorian law of the judgment during the cassation appeal. On February 17, 2012, the appellate panel of the provincial court admitted Chevron’s cassation appeal in a procedural step necessary for the National Court of Justice to hear the appeal. The provincial court appellate panel denied Chevron’s request for suspension of the requirement that Chevron post a bond and stated that it would not comply with the First and Second Interim Awards of the international arbitration tribunal discussed below. On March 29, 2012, the matter was transferred from the provincial court to the National Court of Justice, where the National Court will determine whether it will hear Chevron’s cassation appeal. On October 15, 2012, the provincial court in Lago Agrio issued an ex parte embargo order that purports to order the seizure of assets belonging to separate Chevron subsidiaries in Ecuador, Argentina and Colombia.

Chevron has no assets in Ecuador and the Lago Agrio plaintiffs’ lawyers have stated in press releases and through other media that they will seek to enforce the Ecuadorian judgment in various countries and otherwise disrupt Chevron’s operations. On May 30, 2012, the Lago Agrio plaintiffs filed an action against Chevron Corporation, Chevron Canada Limited, and Chevron Canada Finance Limited in the Ontario Superior Court of Justice in Ontario, Canada, seeking to recognize and enforce the Ecuadorian judgment. On June 27, 2012, the Lago Agrio plaintiffs filed an action against Chevron Corporation in the Superior Court of Justice in Brasilia, Brazil, seeking to recognize and enforce the Ecuadorian judgment. Chevron continues to believe the Ecuadorian provincial court’s judgment is illegitimate and unenforceable in Ecuador, the United States and other countries. The company also believes the judgment is the product of fraud, and contrary to the legitimate scientific evidence. Chevron cannot predict the timing or ultimate outcome of the appeals process in Ecuador or any enforcement action. Chevron expects to continue a vigorous defense of any imposition of liability in the Ecuadorian courts and to contest and defend any and all enforcement actions.

Chevron and Texpet filed an arbitration claim in September 2009 against the Republic of Ecuador before an arbitral tribunal presiding in the Permanent Court of Arbitration in The Hague under the Rules of the United Nations Commission on International Trade Law. The claim alleges violations of the Republic of Ecuador’s obligations under the United States–Ecuador Bilateral Investment Treaty (BIT) and breaches of the settlement and release agreements between the Republic of Ecuador and Texpet (described above), which are investment agreements protected by the BIT. Through the arbitration, Chevron and Texpet are seeking relief against the Republic of Ecuador, including a declaration that any judgment against Chevron in the Lago Agrio litigation constitutes a violation of Ecuador’s obligations under the BIT. On February 9, 2011, the Tribunal issued an Order for Interim Measures requiring the Republic of Ecuador to take all measures at its disposal to suspend or cause to be suspended the enforcement or recognition within and without Ecuador of any judgment against Chevron in the Lago Agrio case pending further order of the Tribunal. On January 25, 2012, the Tribunal converted the Order for Interim Measures into an Interim Award. Chevron filed a renewed application for further interim measures on January 4, 2012, and the Republic of Ecuador opposed Chevron’s application and requested that the existing Order for Interim Measures be vacated on January 9, 2012. On February 16, 2012, the Tribunal issued a Second Interim Award mandating that the Republic of Ecuador take all measures necessary (whether by its judicial,

legislative or executive branches) to suspend or cause to be suspended the enforcement and recognition within and without Ecuador of the judgment against Chevron and, in particular, to preclude any certification by the Republic of Ecuador that would cause the judgment to be enforceable against Chevron. On February 27, 2012, the Tribunal issued a Third Interim Award confirming its jurisdiction to hear Chevron’s arbitration claims. On April 9, 2012, the Tribunal issued a scheduling order to hear issues relating to the scope of the settlement and release agreements between the Republic of Ecuador and Texpet by late November 2012, and on July 9, 2012, the Tribunal indicated that it wanted to hear the remaining issues in January 2014.

Through a series of U.S. court proceedings initiated by Chevron to obtain discovery relating to the Lago Agrio litigation and the BIT arbitration, Chevron obtained evidence that it believes shows a pattern of fraud, collusion, corruption, and other misconduct on the part of several lawyers, consultants and others acting for the Lago Agrio plaintiffs. In February 2011, Chevron filed a civil lawsuit in the Federal District Court for the Southern District of New York against the Lago Agrio plaintiffs and several of their lawyers, consultants and supporters, alleging violations of the Racketeer Influenced and Corrupt Organizations Act and other state laws. Through the civil lawsuit, Chevron is seeking relief that includes an award of damages and a declaration that any judgment against Chevron in the Lago Agrio litigation is the result of fraud and other unlawful conduct and is therefore unenforceable. On March 7, 2011, the Federal District Court issued a preliminary injunction prohibiting the Lago Agrio plaintiffs and persons acting in concert with them from taking any action in furtherance of recognition or enforcement of any judgment against Chevron in the Lago Agrio case pending resolution of Chevron’s civil lawsuit by the Federal District Court. On May 31, 2011, the Federal District Court severed claims one through eight of Chevron’s complaint from the ninth claim for declaratory relief and imposed a discovery stay on claims one through eight pending a trial on the ninth claim for declaratory relief. On September 19, 2011, the U.S. Court of Appeals for the Second Circuit vacated the preliminary injunction, stayed the trial on Chevron’s ninth claim, a claim for declaratory relief, that had been set for November 14, 2011, and denied the defendants’ mandamus petition to recuse the judge hearing the lawsuit. The Second Circuit issued its opinion on January 26, 2012 ordering the dismissal of Chevron’s ninth claim for declaratory relief. On February 16, 2012, the Federal District Court lifted the stay on claims one through eight, and on October 18, 2012, the Federal District Court set a trial date of October 15, 2013.

The ultimate outcome of the foregoing matters, including any financial effect on Chevron, remains uncertain. Management does not believe an estimate of a reasonably possible loss (or a range of loss) can be made in this case. Due to the defects associated with the Ecuadorian judgment, the 2008 engineer’s report on alleged damages and the September 2010 plaintiffs’ submission on alleged damages, management does not believe these documents have any utility in calculating a reasonably possible loss (or a range of loss). Moreover, the highly uncertain legal environment surrounding the case provides no basis for management to estimate a reasonably possible loss (or a range of loss).

Note 10. Other Contingencies and Commitments

Income Taxes The company calculates its income tax expense and liabilities quarterly. These liabilities generally are subject to audit and are not finalized with the individual taxing authorities until several years after the end of the annual period for which income taxes have been calculated. Refer to Note 7 on page 13 for a discussion of the periods for which tax returns have been audited for the company’s major tax jurisdictions.

Settlement of open tax years, as well as tax issues in other countries where the company conducts its businesses, is not expected to have a material effect on the consolidated financial position or liquidity of the company and, in the opinion of management, adequate provision has been made for income and franchise taxes for all years under examination or subject to future examination.

Guarantees The company and its subsidiaries have certain other contingent liabilities with respect to guarantees, direct or indirect, of debt of affiliated companies or third parties. Under the terms of the guarantee arrangements, the company would generally be required to perform should the affiliated company or third party fail to fulfill its obligations under the arrangements. In some cases, the guarantee arrangements may have recourse provisions that would enable the company to recover any payments made under the terms of the guarantees from assets provided as collateral.

Indemnifications The company provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell and Saudi Refining, Inc., in connection with the February 2002 sale of the company’s interests in those investments. Through the end of September 2012, the company had paid $48 million under these indemnities and continues to be obligated up to $250 million for possible additional indemnification payments in the future.

The company has also provided indemnities relating to contingent environmental liabilities related to assets originally contributed by Texaco to the Equilon and Motiva joint ventures and environmental conditions that existed prior to the formation of Equilon and Motiva, or that occurred during the period of Texaco’s ownership interest in the joint ventures. In general, the environmental conditions or events that are subject to these indemnities must have arisen prior to December 2001. Claims had to be asserted by February 2009 for Equilon indemnities and February 2012 for Motiva indemnities. In February 2012, Motiva Enterprises LLC delivered a letter to the company purporting to preserve unmatured claims for certain Motiva indemnities. The letter itself provides no estimate of the ultimate claim amount. Management does not believe this letter or any other information provides a basis to estimate the amount, if any, of a range of loss or potential range of loss with respect to either the Equilon or the Motiva indemnities. Under the terms of these indemnities, there is no maximum limit on the amount of potential future payments. The company posts no assets as collateral and has made no payments under the indemnities.

The amounts payable for the indemnities described in the preceding paragraph are to be net of amounts recovered from insurance carriers and others and net of liabilities recorded by Equilon or Motiva prior to September 30, 2001, for any applicable incident.

In the acquisition of Unocal, the company assumed certain indemnities relating to contingent environmental liabilities associated with assets that were sold in 1997. The acquirer of those assets shared in certain environmental remediation costs up to a maximum obligation of $200 million, which had been reached at December 31, 2009. Under the indemnification agreement, after reaching the $200 million obligation, Chevron is solely responsible until April 2022, when the indemnification expires. The environmental conditions or events that are subject to these indemnities must have arisen prior to the sale of the assets in 1997.

Although the company has provided for known obligations under this indemnity that are probable and reasonably estimable, the amount of additional future costs may be material to results of operations in the period in which they are recognized. The company does not expect these costs will have a material effect on its consolidated financial position or liquidity.

Off-Balance-Sheet Obligations The company and its subsidiaries have certain other contingent liabilities with respect to long-term unconditional purchase obligations and commitments, including throughput and take-or-pay agreements, some of which relate to suppliers’ financing arrangements. The agreements typically provide goods and services, such as pipeline and storage capacity, drilling rigs, utilities, and petroleum products, to be used or sold in the ordinary course of the company’s business.

Environmental The company is subject to loss contingencies pursuant to laws, regulations, private claims and legal proceedings related to environmental matters that are subject to legal settlements or that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemicals or petroleum substances, including MTBE, by the company or other parties. Such contingencies may exist for various sites, including, but not limited to, federal Superfund sites and analogous sites under state laws, refineries, crude oil fields, service stations, terminals, land development areas, and mining operations, whether operating, closed or divested. These future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.

Although the company has provided for known environmental obligations that are probable and reasonably estimable, the amount of additional future costs may be material to results of operations in the period in which they are recognized. The company does not expect these costs will have a material effect on its consolidated

financial position or liquidity. Also, the company does not believe its obligations to make such expenditures have had, or will have, any significant impact on the company’s competitive position relative to other U.S. or international petroleum or chemical companies.

Other Contingencies On April 26, 2010, a California appeals court issued a ruling related to the adequacy of an Environmental Impact Report (EIR) supporting the issuance of certain permits by the city of Richmond, California, to replace and upgrade certain facilities at Chevron’s refinery in Richmond. Settlement discussions with plaintiffs in the case ended late fourth quarter 2010, and on March 3, 2011, the trial court entered a final judgment and peremptory writ ordering the City to set aside the project EIR and conditional use permits and enjoining Chevron from any further work. On May 23, 2011, the company filed an application with the City Planning Department for a conditional use permit for a revised project to complete construction of the hydrogen plant, certain sulfur removal facilities and related infrastructure. On June 10, 2011, the City published its Notice of Preparation of the revised EIR for the project. The revised and recirculated EIR is intended to comply with the appeals court decision. Management believes the outcomes associated with the project are uncertain. Due to the uncertainty of the company’s future course of action, or potential outcomes of any action or combination of actions, management does not believe an estimate of the financial effects, if any, can be made at this time.

Chevron receives claims from and submits claims to customers; trading partners; U.S. federal, state and local regulatory bodies; governments; contractors; insurers; and suppliers. The amounts of these claims, individually and in the aggregate, may be significant and take lengthy periods to resolve.

The company and its affiliates also continue to review and analyze their operations and may close, abandon, sell, exchange, acquire or restructure assets to achieve operational or strategic benefits and to improve competitiveness and profitability. These activities, individually or together, may result in gains or losses in future periods.

Note 11. Fair Value Measurements

Accounting standards for fair value measurement (ASC 820) establish a framework for measuring fair value and stipulate disclosures about fair value measurements. The standards apply to recurring and nonrecurring fair value measurements of financial and nonfinancial assets and liabilities. Among the required disclosures is the fair value hierarchy of inputs the company uses to value an asset or a liability. The three levels of the fair value hierarchy are described as follows:

Level 1: Quoted prices (unadjusted) in active markets for identical assets and liabilities. For the company, Level 1 inputs include exchange-traded futures contracts for which the parties are willing to transact at the exchange-quoted price and marketable securities that are actively traded.

Level 2: Inputs other than Level 1 that are observable, either directly or indirectly. For the company, Level 2 inputs include quoted prices for similar assets or liabilities, prices obtained through third-party broker quotes and prices that can be corroborated with other observable inputs for substantially the complete term of a contract.

Level 3: Unobservable inputs. The company does not use Level 3 inputs for any of its recurring fair value measurements. Level 3 inputs may be required for the determination of fair value associated with certain nonrecurring measurements of nonfinancial assets and liabilities.

The fair value hierarchy for assets and liabilities measured at fair value on a recurring basis at September 30, 2012 and December 31, 2011 is as follows:

Assets and Liabilities Measured at Fair Value on a Recurring Basis

(Millions of dollars)

At September 30, 2012

At December 31, 2011

Total

Level 1

Level 2

Level 3

Total

Level 1

Level 2

Level 3

Marketable Securities

$

261

$

261

$

—

$

—

$

249

$

249

$

—

$

—

Derivatives

86

17

69

—

208

104

104

—

Total Assets at Fair Value

$

347

$

278

$

69

$

—

$

457

$

353

$

104

$

—

Derivatives

172

160

12

—

102

101

1

—

Total Liabilities at Fair Value

$

172

$

160

$

12

$

—

$

102

$

101

$

1

$

—

Marketable Securities The company calculates fair value for its marketable securities based on quoted market prices for identical assets. The fair values reflect the cash that would have been received if the instruments were sold at September 30, 2012.

Derivatives The company records its derivative instruments — other than any commodity derivative contracts that are designated as normal purchase and normal sale — on the Consolidated Balance Sheet at fair value, with the offsetting amount to the Consolidated Statement of Income. For derivatives with identical or similar provisions as contracts that are publicly traded on a regular basis, the company uses the market values of the publicly traded instruments as an input for fair value calculations.

The company’s derivative instruments principally include futures, swaps, options and forward contracts for crude oil, natural gas and refined products. Derivatives classified as Level 1 include futures, swaps and options contracts traded in active markets such as the New York Mercantile Exchange.

Derivatives classified as Level 2 include swaps, options and forward contracts principally with financial institutions and other oil and gas companies, the fair values of which are obtained from third-party broker quotes, industry pricing services and exchanges. The company obtains multiple sources of pricing information for the Level 2 instruments. Since this pricing information is generated from observable market data, it has historically been very consistent. The company does not materially adjust this information. The company incorporates internal review, evaluation and assessment procedures, including a comparison of Level 2 fair values derived from the company’s internally developed forward curves (on a sample basis) with the pricing information to document reasonable, logical and supportable fair value determinations and proper level of classification.

Assets carried at fair value at September 30, 2012 and December 31, 2011 are as follows:

Cash and Cash Equivalents and Time Deposits The company holds cash equivalents and bank time deposits in U.S. and non-U.S. portfolios. The instruments classified as cash equivalents are primarily bank time deposits with maturities of 90 days or less, and money market funds. “Cash and cash equivalents” had carrying/fair values of $21.3 billion and $15.9 billion at September 30, 2012 and December 31, 2011, respectively. The instruments held in “Time deposits” are bank time deposits with maturities greater than 90 days and had carrying/fair values of $8 million and $4.0 billion at September 30, 2012 and December 31, 2011, respectively. The fair values of cash, cash equivalents and bank time deposits are classified as Level 1 and reflect the cash that would have been received if the instruments were settled at September 30, 2012.

Restricted Cash had a carrying/fair value of $1.3 billion and $1.2 billion at September 30, 2012 and December 31, 2011, respectively. At September 30, 2012, restricted cash is classified as Level 1 and is reported in “Deferred charges and other assets” on the face of the Consolidated Balance Sheet, and includes restricted funds related to various capital investment projects, tax payments, and certain Upstream abandonment activities.

The carrying values of other short-term financial assets and liabilities, including short-term debt reclassified to long-term, on the consolidated balance sheet approximate their fair values. Fair value remeasurements of other financial instruments at September 30, 2012 and 2011 were not material.

The fair value hierarchy for assets and liabilities measured at fair value on a nonrecurring basis at September 30, 2012 is as follows:

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

(Millions of dollars)

At September 30, 2012

Before-Tax Loss

Total

Level 1

Level 2

Level 3

Three

Months

Ended

NineMonthsEnded

Properties, plant and equipment, net (held and used)

$

53

$

—

$

—

$

53

$

74

$

97

Properties, plant and equipment, net (held for sale)

—

—

—

—

—

—

Investments and advances

—

—

—

—

—

4

Total Assets at Fair Value

$

53

$

—

$

—

$

53

$

74

$

101

Properties, plant and equipment The company did not have any material impairments of long-lived assets measured at fair value on a nonrecurring basis to report in third quarter2012.

Investments and advances The company did not have any impairments of investments and advances measured at fair value on a nonrecurring basis to report in third quarter2012.

Note 12. Derivative Instruments and Hedging Activities

The company’s derivative instruments principally include crude oil, natural gas and refined product futures, swaps, options, and forward contracts. None of the company’s derivative instruments is designated as a hedging instrument, although certain of the company’s affiliates make such a designation. The company’s derivatives are not material to the company’s financial position, results of operations or liquidity. The company believes it has no material market or credit risks to its operations, financial position or liquidity as a result of its commodities and other derivatives activities.

Derivative instruments measured at fair value at September 30, 2012, and December 31, 2011, and their classification on the Consolidated Balance Sheet and Consolidated Statement of Income are as follows:

Consolidated Statement of Income: The Effect of Derivatives Not Designated as Hedging Instruments

(Millions of dollars)

Gain / (Loss)Three Months EndedSeptember 30

Gain / (Loss)Nine Months EndedSeptember 30

Type of

Contract

Statement of Income Classification

2012

2011

2012

2011

Commodity

Sales and other operating revenues

$

(207

)

$

130

$

(92

)

$

(194

)

Commodity

Purchased crude oil and products

1

(11

)

(10

)

20

Commodity

Other income

3

3

7

1

$

(203

)

$

122

$

(95

)

$

(173

)

Note 13. New Accounting Standards

Balance Sheet (Topic 210), Disclosures about Offsetting Assets and Liabilities (ASU 2011-11) In December 2011, the FASB issued ASU 2011-11, which becomes effective for the company on January 1, 2013. The standard amends and expands disclosure requirements about offsetting and related arrangements. The company does not anticipate any impact to its results of operations, financial position or liquidity when the guidance becomes effective.

Note 14. Long-Term Debt

The net carrying value of long-term debt, excluding amounts reclassified from short-term, at September 30, 2012 and December 31, 2011 is $4.1 billion. The fair value of long-term debt at September 30, 2012 and December 31, 2011 is $4.9 billion. Long-term debt primarily includes corporate issued bonds. The fair value of corporate bonds is $4.0 billion and classified as Level 1. The fair value of the other bonds is $0.9 billion and classified as Level 2.

Note 15. Accounting for Suspended Exploratory Wells

Accounting standards for the costs of exploratory wells (ASC 932) provide that exploratory well costs continue to be capitalized after the completion of drilling when (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met or if an entity obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well would be assumed to be impaired, and its costs, net of any salvage value, would be charged to expense. (Note that an entity is not required to complete the exploratory well as a producing well.) The company’s capitalized cost of suspended wells at September 30, 2012, was $2.6 billion, a net increase of $182 million from year-end 2011, primarily due to drilling activities in Australia and Canada. For the category of exploratory well costs at year-end 2011 that were suspended more than one year, a total of $46 million was expensed in the first nine months of 2012.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Third Quarter 2012 Compared with Third Quarter 2011

And Nine Months2012 Compared with Nine Months2011

Key Financial Results

Earnings by Business Segment

Three Months EndedSeptember 30

Nine Months Ended September 30

2012

2011

2012

2011

(Millions of dollars)

Upstream

United States

$

1,122

$

1,508

$

3,969

$

4,907

International

4,017

4,693

12,961

14,142

Total Upstream

5,139

6,201

16,930

19,049

Downstream

United States

456

704

1,717

1,710

International

233

1,282

1,657

1,942

Total Downstream

689

1,986

3,374

3,652

Total Segment Earnings

5,828

8,187

20,304

22,701

All Other

(575

)

(358

)

(1,370

)

(929

)

Net Income Attributable to Chevron Corporation(1)(2)

$

5,253

$

7,829

$

18,934

$

21,772

(1) Includes foreign currency effects

$

(293

)

$

449

$

(323

)

$

204

(2) Also referred to as “earnings” in the discussions that follow.

Net income attributable to Chevron Corporation for third quarter2012 was $5.3 billion ($2.69 per share — diluted), compared with $7.8 billion ($3.92 per share — diluted) in the corresponding 2011 period. Net income attributable to Chevron Corporation for the first nine months of 2012 was $18.9 billion ($9.62 per share — diluted), versus $21.8 billion ($10.86 per share — diluted) in the first nine months of 2011.

Upstream earnings in third quarter2012 were $5.1 billion, compared with $6.2 billion in the 2011 quarter. The decrease was mainly due to lower crude oil volumes and realizations. Earnings for the first nine months of 2012 were $16.9 billion, versus $19.0 billion a year earlier. The decrease between the comparative periods was mainly due to lower crude oil volumes, higher exploration expenses and higher operating expenses. Partially offsetting these effects was a nearly $600 million gain on sale of an equity interest in the Wheatstone project.

Downstream earnings were $689 million in third quarter2012, compared with $2.0 billion in the year-earlier period. The decline was mainly due to lower gains on asset sales, an unfavorable change in effects on derivative instruments, and lower margins. Earnings for the first nine months of 2012 were $3.4 billion, versus $3.7 billion in the corresponding 2011 period. The decrease between comparative periods was mainly due to a decline in gains from asset sales.

Refer to pages 28 through 30 for additional discussion of results by business segment and “All Other” activities for third quarter and first nine months of 2012 versus the same period in 2011.

Business Environment and Outlook

Chevron is a global energy company with substantial business activities in the following countries: Angola, Argentina, Australia, Azerbaijan, Bangladesh, Brazil, Cambodia, Canada, Chad, China, Colombia, Democratic Republic of the Congo, Denmark, Indonesia, Kazakhstan, Myanmar, the Netherlands, Nigeria, Norway, the Partitioned Zone between Saudi Arabia and Kuwait, the Philippines, Republic of the Congo, Singapore, South Africa, South Korea, Thailand, Trinidad and Tobago, the United Kingdom, the United States, Venezuela, and Vietnam.

Earnings of the company depend mostly on the profitability of its upstream and downstream business segments. The single biggest factor that affects the results of operations for the company is movement in the price of crude oil. In the downstream business, crude oil is the largest cost component of refined products. Seasonality is not a primary driver of changes in the company’s quarterly earnings during the year.

To sustain its long-term competitive position in the upstream business, the company must develop and replenish an inventory of projects that offer attractive financial returns for the investment required. Identifying promising areas for exploration, acquiring the necessary rights to explore for and to produce crude oil and natural gas, drilling successfully, and handling the many technical and operational details in a safe and cost-effective manner are all important factors in this effort. Projects often require long lead times and large capital commitments.

The company’s operations, especially upstream, can also be affected by changing economic, regulatory and political environments in the various countries in which it operates, including the United States. From time to time, certain governments have sought to renegotiate contracts or impose additional costs on the company. Governments may attempt to do so in the future. Civil unrest, acts of violence or strained relations between a government and the company or other governments may impact the company’s operations or investments. Those developments have at times significantly affected the company’s operations and results and are carefully considered by management when evaluating the level of current and future activity in such countries.

The company also continually evaluates opportunities to dispose of assets that are not expected to provide sufficient long-term value or to acquire assets or operations complementary to its asset base to help augment the company’s financial performance and growth. Refer to the “Results of Operations” section, beginning on page 28, for discussions of net gains on asset sales during 2012. Asset dispositions and restructurings may also occur in future periods and could result in significant gains or losses.

The company closely monitors developments in the financial and credit markets, the level of worldwide economic activity, and the implications for the company of movements in prices for crude oil and natural gas. Management takes these developments into account in the conduct of daily operations and for business planning.

Comments related to earnings trends for the company’s major business areas are as follows:

Upstream Earnings for the upstream segment are closely aligned with industry price levels for crude oil and natural gas. Crude oil and natural gas prices are subject to external factors over which the company has no control, including product demand connected with global economic conditions, industry inventory levels, production quotas imposed by the Organization of Petroleum Exporting Countries (OPEC), weather-related damage and disruptions, competing fuel prices, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty. Any of these factors could also inhibit the company’s production capacity in an affected region. The company monitors developments closely in the countries in which it operates and holds investments, and seeks to manage risks in operating its facilities and businesses. The longer-term trend in earnings for the upstream segment is also a function of other factors, including the company’s ability to find or acquire and efficiently produce crude oil and natural gas, changes in fiscal terms of contracts and changes in tax laws and regulations.

The company continues to actively manage its schedule of work, contracting, procurement and supply-chain activities to effectively manage costs. However, price levels for capital and exploratory costs and operating expenses associated with the production of crude oil and natural gas can be subject to external factors beyond the company’s control. External factors include not only the general level of inflation, but also commodity prices and prices charged by the industry’s material and service providers, which can be affected by the volatility of the industry’s own supply-and-demand conditions for such materials and services. Capital and exploratory expenditures and operating expenses can also be affected by damage to production facilities caused by severe weather or civil unrest.

The chart above shows the trend in benchmark prices for Brent crude oil, West Texas Intermediate (WTI) crude oil, and U.S. Henry Hub natural gas. The Brent price averaged $111 per barrel for the full-year 2011. During third quarter 2012, Brent averaged $110 per barrel and ended October at about $110. The WTI price averaged $95 per barrel for the full-year 2011. During third quarter 2012, WTI averaged $92 per barrel and ended October at about $86. The majority of the company’s equity crude production is priced based on the Brent benchmark. WTI traded at a discount to Brent throughout 2011 and 2012 due to high inventories in the U.S. Midcontinent market driven by strong growth in domestic production.

A differential in crude oil prices exists between high quality (high-gravity, low-sulfur) crudes and those of lower quality (low-gravity, high-sulfur). The amount of the differential in any period is associated with the supply of heavy crude available versus the demand, which is a function of the capacity of refineries that are able to process this lower quality feedstock into light products (motor gasoline, jet fuel, aviation gasoline and diesel fuel). The differential widened in the third quarter of 2012 primarily due to strong diesel prices and low petroleum product inventories.

Chevron produces or shares in the production of heavy crude oil in California, Chad, Indonesia, the Partitioned Zone between Saudi Arabia and Kuwait, Venezuela and in certain fields in Angola, China and the United Kingdom sector of the North Sea. (See page 33 for the company’s average U.S. and international crude oil realizations.)

In contrast to price movements in the global market for crude oil, price changes for natural gas in many regional markets are more closely aligned with supply-and-demand conditions in those markets. In the United States, prices at Henry Hub averaged $2.51 per thousand cubic feet (MCF) in the first nine months of 2012, compared with $4.24 during the first nine months of 2011. At the end of October 2012, the Henry Hub spot price was $3.51 per MCF. Fluctuations in the price for natural gas in the United States are closely associated with customer demand relative to the volumes produced in North America. The Henry Hub gas price declined during first quarter 2012 due to high inventories resulting from a mild winter and continued growth in U.S. gas production. The Henry Hub price has strengthened since April due to strong gas demand for power generation, flat production and less surplus inventories.

Outside the United States, price changes for natural gas depend on a wide range of supply, demand and regulatory circumstances. In some locations, Chevron is investing in long-term projects to install infrastructure to produce and liquefy natural gas for transport by tanker to other markets. International natural gas realizations averaged $6.00 per MCF during the first nine months of 2012, compared with $5.33 in the same period last year. (See page 33 for the company’s average natural gas realizations for the U.S. and international regions.)

The company’s worldwide net oil-equivalent production in the first nine months of 2012 averaged 2.59 million barrels per day. About one-fifth of the company’s net oil-equivalent production in the first nine months of 2012 occurred in the OPEC-member countries of Angola, Nigeria, Venezuela and the Partitioned Zone between Saudi Arabia and Kuwait. OPEC quotas had no effect on the company’s net crude oil production for third quarter2012 or 2011. At their latest meeting in June 2012, members of OPEC supported maintaining the collective production ceiling of 30 million barrels per day agreed upon in December 2011.

Production in any given year is subject to many factors and uncertainties, including additional quotas that may be imposed by OPEC, price effects on entitlement volumes, changes in fiscal terms or restrictions on the scope of company operations, delays in project startups or ramp-ups, or fluctuations in demand for natural gas in various markets, weather conditions that may shut in production, civil unrest, changing geopolitics, delays in completion of maintenance turnarounds, greater-than-expected declines in production from mature fields, or other disruptions to operations. The outlook for future production levels is also affected by the size and number of economic investment opportunities and, for new large-scale projects, the time lag between initial exploration and the beginning of production. Investments in upstream projects generally begin well in advance of the start of the associated crude oil and natural gas production. A significant majority of Chevron’s upstream investment is made outside the United States.

The company estimates that net oil-equivalent production for the full-year 2012 will average about 97 percent of the previously-announced target of 2.680 million barrels per day. The production shortfall is primarily due to the shut-in of the Frade Field in Brazil and the timing of start-up of LNG production in Angola.

On November 7, 2011, while drilling a development well in the deepwater Frade Field about 75 miles offshore Brazil, an unanticipated pressure spike caused oil to migrate from the well bore through a series of fissures to the sea floor, emitting approximately 2,400 barrels of oil. Upon detection, the company immediately took steps to stop the release. Chevron’s emergency plan, approved by the Brazilian environment and natural resources regulatory agency IBAMA, was implemented according to the law and industry standards. The source of the seep was substantially contained within four days and the well has been plugged and abandoned. No evidence of any coastal or wildlife impacts related to this seep has emerged. On March 14, 2012, the company identified a small, second seep in a different part of the field. As a precautionary measure, the company and its partners decided to temporarily suspend field production and received approval from Brazil’s National Petroleum Agency (ANP) to do so. The company also installed special containment devices on the seafloor to capture the oil and will install additional devices if needed. Chevron and its partners continue to cooperate with the Brazilian authorities and are conducting studies to better understand the geology in the area. On July 19, 2012, ANP issued its final investigative report on the November 2011 incident. On August 16, 2012, Chevron submitted to ANP a plan for restarting limited production in the Frade field. A Brazilian federal district prosecutor has filed two civil lawsuits seeking $10.7 billion in damages for each of the two seeps. The company is not aware of any basis for damages to be awarded in any civil lawsuit. On July 31, 2012, a court presiding over the civil litigation entered a preliminary injunction barring Chevron from conducting oil production and transportation activities in Brazil pending completion of the legal proceedings commenced by the federal prosecutor and the ongoing proceedings of ANP and IBAMA. On September 28, 2012, the injunction was modified to clarify that Chevron may continue its containment and mitigation activities under supervision of ANP. The federal prosecutor has also filed criminal charges against 11 Chevron employees. With regard to criminal charges, the company believes them to be without merit and intends to aggressively defend the company and the named employees. Jurisdiction has been moved for all three matters from Campos to a court in Rio de Janeiro. The company’s ultimate exposure related to the incident is not currently determinable, but could be significant to net income in any one period.

The company entered into a non-binding financing term sheet with Petroboscan, a joint stock company owned 39.2 percent by Chevron, which operates the Boscan Field in Venezuela. When finalized, the financing is expected to occur in stages over a limited drawdown period and is intended to support a specific work program to maintain and increase production to an agreed-upon level. The terms are designed to support cash needs for on-going operations and new development, as well as distributions to shareholders — including current outstanding obligations. The loan will be repaid from future Petroboscan crude sales. Definitive documents are under negotiation.

Refer to the “Results of Operations” section on pages 28 through 29 for additional discussion of the company’s upstream business.

Downstream Earnings for the downstream segment are closely tied to margins on the refining, manufacturing and marketing of products that include gasoline, diesel, jet fuel, lubricants, fuel oil, fuel and lubricant additives, and petrochemicals. Industry margins are sometimes volatile and can be affected by the global and regional supply-and-demand balance for refined products and petrochemicals and by changes in the price of crude oil, other refinery and petrochemical feedstocks, and natural gas. Industry margins can also be influenced by

Other factors affecting profitability for downstream operations include the reliability and efficiency of the company’s refining, marketing and petrochemical assets, the effectiveness of the crude oil and product supply functions, and the volatility of tanker-charter rates for the company’s shipping operations, which are driven by the industry’s demand for crude oil and product tankers. Other factors beyond the company’s control include the general level of inflation and energy costs to operate the company’s refining, marketing and petrochemical assets.

The company’s most significant marketing areas are the West Coast of North America, the U.S. Gulf Coast, Asia and southern Africa. Chevron operates or has significant ownership interests in refineries in each of these areas. The company has further progressed its ongoing effort to concentrate downstream resources and capital on strategic assets. In March 2012, the company completed the sale of its fuels and finished lubricants businesses in Spain. In July 2012, the company completed the sale of its Perth Amboy, New Jersey, refinery, which had been operated as a products terminal in recent years. In April and July 2012, the company completed the sales of several of its fuels marketing and aviation businesses in the Caribbean, and expects to complete the remaining announced sales of certain fuels marketing and aviation businesses in the Caribbean during the fourth quarter of 2012.

In July 2012, Caltex Australia Ltd. (CAL), the company’s 50 percent-owned affiliate, announced that it plans to convert its Kurnell Refinery to an import terminal in 2014. As a result of this decision, Chevron recognized restructuring-related charges which are not material to its consolidated results of operations.

Refer to the “Results of Operations” section on pages 29 through 30 for additional discussion of the company’s downstream operations.

Noteworthy operating developments for the upstream business in recent months included the following:

•

Australia - Completed the acquisition of additional interest in the Clio and Acme fields in the Carnarvon Basin in exchange for Chevron's interest in the Browse development. Consolidating interests in the Carnarvon Basin fits strategically with long-term plans to grow the Wheatstone area resource base, and create expansion opportunities for the Wheatstone Project.

•

Australia - Completed the sale of an equity interest in the Wheatstone Project to Tokyo Electric.

•

Australia - Announced two natural gas discoveries, Satyr-2 and Satyr-4, in the Carnarvon Basin in 50 percent-owned Block WA-374-P.

United States - Announced an agreement to acquire additional acreage in New Mexico. The acreage is located in the Delaware Basin where the company is already one of the largest leaseholders.

In the downstream business, the company's 50 percent-owned Chevron Phillips Chemical Company LLC announced that its 35 percent-owned Saudi Polymers Company began commercial production at its petrochemical project in Al-Jubail, Saudi Arabia. Also in the third quarter, the company completed the sale of its idled Perth Amboy, New Jersey, refinery, which had been operating as a terminal, and two of its fuels marketing businesses in the Caribbean.

The company purchased $1.25 billion of its common stock in third quarter2012 under its share repurchase program.

Business Segments The following section presents the results of operations for the company’s business segments — Upstream and Downstream — as well as for “All Other.” (Refer to Note 4, on page 9, for a discussion of the company’s “reportable segments,” as defined under the accounting standards for segment reporting.)

Upstream

Three Months EndedSeptember 30

Nine Months Ended September 30

2012

2011

2012

2011

(Millions of dollars)

U.S. Upstream Earnings

$

1,122

$

1,508

$

3,969

$

4,907

U.S. upstream earnings of $1.12 billion in third quarter2012 decreased $386 million from the same period last year. The decrease was due to lower crude oil and natural gas realizations of about $150 million and $90 million, respectively, and decreased net oil-equivalent production of about $95 million.

Earnings for the first nine months of 2012 were $3.97 billion, down $938 million from the corresponding period in 2011. The decrease was primarily due to lower crude oil production of $310 million, lower natural gas realizations of $300 million, higher operating expenses of $100 million and an absence of gains on assets sales of $110 million.

The company’s average realization per barrel of crude oil and natural gas liquids in third quarter2012 was $91, down from $97 a year earlier. For both of the nine-month periods, average realizations were $97. The average natural gas realization in third quarter2012 was $2.63 per thousand cubic feet, compared with $4.14 in the year-ago period. The average nine-month realizations were $2.43 in 2012 and $4.18 in 2011.

Net oil-equivalent production of 637,000 barrels per day in third quarter2012 was down 25,000 barrels per day, or about 4 percent, from a year earlier. The decrease in production was associated with normal field declines and an absence of volumes associated with Cook Inlet, Alaska, assets sold in 2011, and the effects of storm-related shut-ins in 2012 in the Gulf of Mexico. Partially offsetting this decrease was ramp-up at the Perdido and Caesar/Tonga projects in the Gulf of Mexico.

Nine months 2012 production was 649,000 barrels per day, down 35,000 from the corresponding 2011 period. The decrease was associated with normal field declines and an absence of volumes associated with Cook Inlet, Alaska, assets sold in 2011. Partially offsetting this decrease was production from continued ramp-up at the Perdido and Caesar/Tonga projects in the Gulf of Mexico, as well as volumes from the Marcellus Shale.

The net liquids component of oil-equivalent production was 440,000 barrels per day and 452,000 barrels per day for third quarter and nine months of 2012, respectively. Those volumes were 3 percent and 4 percent lower than the corresponding 2011 periods, respectively. Net natural gas production was 1.18 billion cubic feet per day in both 2012 periods, decreasing 6 percent and 8 percent from the comparative third quarter and 9 months 2011 periods, respectively. Excluding the impact of the Cook Inlet assets sold in 2011, natural gas production was essentially flat for the quarterly period and decreased 1% for the first nine months of 2012.

Three Months EndedSeptember 30

Nine Months Ended September 30

2012

2011

2012

2011

(Millions of dollars)

International Upstream Earnings*

$

4,017

$

4,693

$

12,961

$

14,142

____________________

* Includes foreign currency effects

$

(252

)

$

304

$

(241

)

$

214

International upstream earnings of $4.0 billion in third quarter2012 decreased $676 million from the corresponding period in 2011. The decline between quarters was primarily due to lower crude oil volumes of about $440 million and lower realizations for crude oil of about $210 million, as well as higher exploration expense of about $240 million. Partially offsetting these effects was a nearly $600 million gain on sale of an equity interest in the Wheatstone Project and lower tax items of about $200 million. Foreign currency effects decreased earnings by $252 million in the 2012 quarter, compared with an increase of $304 million a year earlier.

Earnings for the first nine months of 2012 were $12.96 billion, down $1.18 billion from the same period in 2011. The decrease was mainly due to lower crude oil volumes of about $1.1 billion, higher exploration expenses of about $450 million, higher operating expenses of about $240 million and higher depreciation expense of about $200 million. Partially offsetting these effects was a benefit of higher crude oil and natural gas realizations of about $700 million and a nearly $600 million gain on sale of an equity interest in the Wheatstone Project. Foreign currency effects decreased earnings by $241 million in the first nine months of 2012, compared with an increase of $214 million a year earlier.

The average realization per barrel of crude oil and natural gas liquids in third quarter2012 and nine-month period were $98 and $103, respectively, compared with $103 and $102 in the corresponding 2011 periods. The average natural gas realization per thousand cubic feet in third quarter2012 was $6.03, compared with $5.50 in the corresponding 2011 period. Between the nine-month periods, the average natural gas realization increased to $6.00 from $5.33.

International net oil-equivalent production of 1.88 million barrels per day in third quarter2012 decreased 58,000 barrels per day from a year ago. Production increases from project ramp-ups in Thailand and Nigeria were more than offset by planned maintenance-related downtime, continued shut-in of the Frade Field in Brazil and normal field declines.

International net oil-equivalent production of 1.94 million barrels per day for the nine months of 2012 decreased 59,000 barrels per day from a year ago. Production increases from project ramp-ups in Thailand and Nigeria were more than offset by normal field declines, maintenance-related downtime and the shut-in of the Frade Field in Brazil.

The net liquids component of oil-equivalent production was 1.25 million barrels per day in third quarter2012 and 1.30 million barrels per day in the nine-month period, decreases of 8 and 6 percent for the respective periods. Net natural gas production totaled 3.78 billion cubic feet per day in third quarter2012 and 3.84 billion cubic feet per day in the first nine months, increases of 8 percent and 5 percent, from the respective 2011 periods.

Downstream

Three Months EndedSeptember 30

Nine Months Ended September 30

2012

2011

2012

2011

(Millions of dollars)

U.S. Downstream Earnings

$

456

$

704

$

1,717

$

1,710

U.S. downstream earned $456 million in third quarter2012, compared with earnings of $704 million a year earlier. The decline was mainly due to lower margins on refined product sales of $190 million and higher operating expenses of $60 million.

Earnings of $1.7 billion for the first nine months of 2012 were essentially flat with the corresponding 2011 period.

Refinery crude-input of 779,000 barrels per day in third quarter 2012 and 877,000 barrels per day for the nine-month period decreased 13 percent and 1 percent, respectively, from the corresponding 2011 periods, primarily due to an early-August fire at the refinery in Richmond, California.

Refined product sales of 1.18 million barrels per day in the quarterly period and 1.23 million barrels per day for the nine months of 2012 declined 5 percent and 3 percent, respectively, mainly due to lower gasoline sales. Branded gasoline sales in the third quarter 2012 decreased 2 percent to 519,000 barrels per day.For the nine months of 2012, branded gasoline sales were essentially flat.

International downstream operations earned $233 million in third quarter2012, compared with $1.3 billion a year earlier. Current quarter earnings decreased due to lower gains on asset sales, including the absence of a 2011 gain of approximately $500 million from the sale of the Pembroke Refinery and related marketing assets in the United Kingdom and Ireland. An unfavorable change in effects on derivative instruments of $180 million also contributed to the lower earnings in the 2012 quarter. Foreign currency effects decreased earnings by $43 million in the 2012 quarter, compared with an increase of $148 million a year earlier.

Earnings for the first nine months of 2012 were $1.7 billion, compared with $1.9 billion in the corresponding 2011 period. Earnings decreased due to lower gains on asset sales of approximately $270 million. Foreign currency effects decreased earnings by $76 million in 2012, compared with an increase of $16 million a year earlier.

Refinery crude-input of 909,000 barrels per day in third quarter2012 increased 27,000 barrels per day from third quarter2011. For the nine months of 2012, crude oil inputs were 853,000 barrels per day, down 124,000 barrels per day from the year-ago period, mainly due to the third quarter 2011 sale of the Pembroke Refinery in the United Kingdom.

Total refined product sales of 1.56 million barrels per day for the quarterly period and 1.55 million barrels per day for the first nine months of 2012 were 2 percent and 11 percent lower, respectively, primarily related to the third quarter 2011 sale of the company’s refining and marketing assets in the United Kingdom and Ireland. Excluding the impact of 2011 asset sales, sales volumes were up 3 percent for the quarterly period and remained unchanged for the first nine months of 2012.